Hydrocarbons are sometimes stored or otherwise located in subterranean caverns. Such caverns may be formed by lowering a tubing string down a borehole into salt deposits and introducing water downhole through the tubing to dissolve the salt and create a cavern. The borehole itself can be uncased (i.e. an open wellbore) or cased, typically with a steel casing. A large amount of brine is produced from such a process, some of which fills the cavern and borehole and some of which is removed, such as to a brine pond.
A fluid that is desired to be stored in the cavern, such as a liquefied or gaseous hydrocarbon, can be introduced into the cavern through the borehole via the tubing string or the annular space between the borehole and the tubing string, resulting in an interface between the fluid to be stored and brine that moves progressively downward as the fluid is injected. As a result, brine is urged upward through the tubing string or annulus into a brine pond or elsewhere for disposal and/or storage.
An issue associated with such storage of hydrocarbons in an underground cavern is the potential leakage of the stored hydrocarbons out of the cavern or borehole and into the surrounding formation, which can lead to contamination of nearby water deposits from which drinking water may be pumped, or other catastrophic consequences such as a blowout, creation of a sinkhole, or gas leakage into the atmosphere. Consequently, various government regulatory agencies have required that caverns for storing hydrocarbons be tested for mechanical integrity to determine the rate of leakage therefrom.
Mechanical integrity testing (MIT) typically involves filling the storage cavern with brine and injecting a test fluid, such as nitrogen or a liquid hydrocarbon, into the brine-filled cavern via the annulus so as to form a fluid interface between the brine and test fluid. The borehole is then capped and the interface is observed over a period of time until a minimum detectable leak rate (MDLR) is detected. Movement of the fluid interface and/or other borehole conditions are observed and interpreted to determine the presence of a leak. For example, a rise in the interface may indicate leakage of test fluid into the surrounding formation, and a lowering of the interface may indicate leakage of brine out of the cavern. The volume of test fluid that has leaked into the surrounding formation can be determined by calculating the volume of the section of borehole defined by the level of the interface at the beginning of the test period and the level of the interface at the end of the test period, while accounting for interface movement due to fluid volume changes caused by fluctuations in temperature and pressure in the borehole during the test period. Fluid leakage typically occurs near the casing shoe adjacent the bottom of the borehole, or through the casing. As such, the test fluid/brine interface is typically located below and adjacent to the bottom of the borehole or the casing shoe. The location of the interface is selected depending on the characteristics of each well such that the interface ideally does not rise above the casing shoe or enter into the larger part of the cavern, as this could potentially interfere with, or void, the MIT test results. Liquid hydrocarbon is often used in place of nitrogen for MITs in older caverns, as such caverns may not have been designed to hold the nitrogen pressure in the upper section of the borehole.
During an MIT test, the level of the brine/test fluid interface can be monitored by an interface detection device such as a pulsed neutron tool configured to perform a neutron survey. However, if the interface is a liquid hydrocarbon/brine interface where hydrogen contents are similar, or there is foam and/or an oil film formed by liquid hydrocarbons such as diesel on top of the brine, the neutron tool's ability to accurately locate the interface deteriorates. Foaming in storage caverns is fairly common, as salt caverns are typically used for hydrocarbon storage. Additionally, a pulsed neutron tool requires about 20 minutes to “calm down” excited neutrons after acquiring a spot reading before the next reading can be taken, resulting in substantial periods of idling while waiting for the neutron tool to prepare for the next reading.
The drawbacks of using a pulsed neutron tool may be addressed by using a density logging tool based on gamma ray scattering and photoelectric absorption to locate the brine/test fluid interface. Such a tool is not affected by the presence of foam or oil film, and does not require a calming down period. Additionally, specifically designed density logging tools can achieve relatively higher vertical resolution compared to pulsed neutron tools. For example, density logging tools can have a resolution of about 5 cm compared to pulsed neutron tools, which typically have a resolution of about 25 cm. As the time required to calculate the MDLR is proportional to the resolution of the interface detection tool, using the CSA Z341 standard formula:
  T  =            V      ×      R      ×      365      ⁢                          ⁢              days        /        year            ×      24      ⁢                          ⁢              hours        /        day                    160      ⁢                          ⁢                        m          3                /        year            where
T=duration of the MIT test in hours,
V=unit annular volume of casing in m3/m, and
R=resolution of the interface tool in meters,
density logging tools can provide substantially shorter MIT testing periods compared to pulsed neutron tools.
However, existing density tools are made for open-hole logging environments and do not emit sufficient energy to penetrate through steel tubing and/or inner casing to detect the interface in cased wellbore environments. Further, existing gamma ray density tools use Cesium-137 as a gamma ray source, which possesses a half-life of 30.5 years. Consequently, such tools pose a severe environmental risk, as it would take more than 150 years, or about five half-lives, for the Cesium-137 gamma ray source to decay to an acceptable level in the event that the density tool is lost in the cavern, for example if the tool is accidentally run too far into the cavern and cannot be recovered. If a Cesium-137 gamma ray source is lost in a cavern, the Canadian Nuclear Safety Commission requires that the well/cavern be abandoned. Given the substantial environment, health, and economic risks associated with the use of a Cesium-137 based gamma ray source, such density tools are not in popular use, despite its effectiveness in detecting the brine/test fluid interface in cased and open wellbore environments and the advantages it offers over a pulsed neutron tool.
Other gamma ray sources having shorter half-lives, such as Cobalt-60 and Iodine-131, may be used in place of Cesium-137 to mitigate the environmental risk. However, Cobalt-60 still has a relatively long half-life of 5.2 years, while Iodine only has a half-life of 8 days, which presents operational difficulties, as MIT tests can have a duration that exceeds 8 days.
As mentioned above, borehole pressure and temperature must also be measured during MIT procedures to account for their effects on the interface depth during the test period, such that interface movement caused by temperature and pressure changes is not misinterpreted as fluid leakage. During conventional MIT testing, well temperature is measured by means of a temperature survey conducted typically from surface to 15 meters below the test fluid/brine interface. Temperature surveys are usually performed before injection of test fluid, at the beginning of the MIT test period, and at the end of the test period. The downhole temperature or an average temperature calculated from the temperature surveys are used to represent the temperature of the well before and after the MIT. In Alberta, Canada, caverns in bedded salt formations are typically 1400 to 2000 meters deep. Given a log rate of 360-600 m/hr, it takes the logging tool approximately 3.5 hours to run a temperature survey for the entire test interval. As a result, the temperature and gas constants of the well at shallower depths may have changed by the time the logging tool reaches the bottom of the test interval, leading to inaccurate wellbore temperature calculations, and in turn inaccurate fluid leakage calculations. Additionally, as only the temperature average is used, conventional MIT techniques do not account for local temperature variations along the test interval that may affect the accuracy of calculations of test fluid leakage.
Further, measurements of wellbore pressure are typically only taken at the wellhead or surface, and no downhole pressure measurements are taken. As the density of the test fluid and brine are only spot measured, and the density of test fluid can change after it is injected into the cavern, the hydrostatic head or downhole pressure is only an estimate, which can result in inaccurate calculations of fluid leakage.
In conventional MIT procedures, if a leak is detected, the leak must be located through additional testing procedures after the initial MIT procedure. For example, wellbore acoustic noise can be logged by running a noise logging tool down the borehole to detect an acoustic signature that is indicative of a leak. As noise logs are typically performed by running the logging tool from the designated depth to surface, the movement of the noise logging tool itself can also induce noise in the wellbore and produce false results. Typically, no wellbore noise measurements are taken during the MIT procedure. Alternatively, or additionally, borehole temperature can be logged again to detect temperature anomalies, such as an abrupt drop in temperature that may be indicative of a leak. Further, a joint-by-joint pressure test may be performed for the entire test interval to detect a pressure drop that suggests a leak.
The lack of accurate and timely wellbore temperature, pressure, and noise measurements all contribute to a greater risk of inaccurate calculations in MIT testing and consequently a greater risk of undetected leakage or inaccurate leakage calculations.
There is a need for a system and method of performing MITs that provides for more accurate and timely temperature and pressure readings, accounts for local temperature variations along the test interval, and enables measurement of wellbore noise. Further, there is a need for a method and system for quickly and accurately locating the brine/test fluid interface during MIT of a storage cavern without the risks associated with a density tool having a Cesium-137 gamma ray source.